Directional drilling is the practice of drilling non-vertical wellbores for the purpose of recovering oil and/or gas and for the utility horizontal directional drilling (HDD) sector. This is achieved by control of the lowermost part of the drillstring, also known as a bottom hole assembly (BHA). Typically a BHA comprises (from the bottom up in a vertical drills string) a bit, a mud motor (incorporating a bend in a steerable system), stabilizers, drill collars, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The BHA must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Often the BHA includes a mud motor, directional drilling and measuring equipment (directional tools'), measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.
Typically, in order to drill a wellbore that deviates from vertical, a bend (positioned above or within the mud motor housing) places the longitudinal axis of bit away from the axis of the drillstring by between about 0.5° and 3.0°. This slight change in direction at the end of the drillstring is sufficient to enable the direction of drilling to be controlled by adjusting the weight on the bit and/or the angular position of the bend in the wellbore. A greater weight on bit causes a larger deviation from the present axis of the wellbore and vice-versa.
It is important to monitor the direction of drilling so that a desired target can be reached from the surface, perhaps following a predetermined path. To that end, the BHA comprises a directional tool whose function is to send data to the surface representing the present position of the bend so that, if needed, adjustments can be made by rotating the drillstring and/or controlling the weight on bit. The directional tool is often positioned behind the mud motor.
At present magnetic directional tools are used almost exclusively for open hole directional borehole drilling trajectory monitoring and control within the oilfield well construction and utility (e.g. river crossing) horizontal directional drilling sectors. The directional tool is normally installed along the axis of the BHA of the drillstring.
The directional tool comprises a number of sensors whose outputs may be analyzed to determine the orientation of the tool (and therefore of the bit). Often the sensors comprise an orthogonal triad of inertial grade accelerometers and a triad of orthogonal precision magnetometers, from which the attitude of the instrument body can be determined from instrument vector measurements of the earths gravitational and magnetic field respectively. The magnetometers and accelerometers are arranged within the directional tool so that one of each type is oriented on an X, Y and Z axis respectively. Usually the X and Y axes are mutually perpendicular and perpendicular to the longitudinal axis of the directional tool. Usually, the Z axis is perpendicular to both the X and Y axes and is parallel to the longitudinal axis of the directional tool. The instrument highside is the roll angle (usually resolved over 360 degrees) from a lateral instrument reference (usually measured from the gravity X or gravity Y axis) to a vertical plane above and along the Z axis of the instrument.
When the directional tool is installed into the BHA, there is generally some angular offset between the angle direction (perpendicular to the BHA axis) in which the bend points and a directional instrument highside angle. This angular offset is measured on-site before the BHA goes downhole. The offset is used to adjust the orientation reference provided by the directional tool so that the driller is informed about angular measurements of the BHA bend from the highside of the borehole. The indication of angular direction of the bend from the borehole highside is known as the ‘gravity toolface’ measurement. Often this direction is displayed to the driller on a circular dial on which the toolface is marked. In use, the output from each sensor is converted from analog to digital and samples are then averaged and processed with the outputs of the other sensors in order to provide a gravity toolface measurement.
Normally, borehole surveys are taken when the drillstring is stationary, following a completion of a ‘kelly down’ and prior to the addition of a stand or drillpipe length and recommencement of drilling activity. Under these conditions, the drillpipe is stationary and stable readings from the directional instrument can be readily obtained.
Drilling with a steerable (sliding) assembly, when power to drive the drill bit is obtained from a mud motor within the BHA, drilling directional control is effected by rotary positioning of the BHA via the drill rig rotary table or top drive. Such an arrangement permits both drilling and steering to take place simultaneously. However, since the BHA is subject to drilling induced vibrations (which are often random 3-axis vibrations comprising frequencies generally in the range 5-500 Hz), any gravity toolface measurements taken whilst drilling can be unstable or exhibit excessive swings in readings. This makes accurate tracking of wellbore direction more difficult and in some circumstances drilling still has to be stopped periodically to check wellbore direction.
Nevertheless some operators attempt to obtain ‘surveys on the fly’ whilst running a steerable assembly and rely on fast data acquisition and fairly sophisticated averaging techniques to obtain quantitative steering and survey data.
There are other rotary drilling and steering applications that rely on directional instruments, for example: survey acquisition and trajectory control, such as Inclination at the Bit, rotary assembly inclination and surveying, geosteering and Rotary Steerable Systems (RSS), the latter of which relies on roll stabilization of an inertial platform for active gravity toolface control or full (inclination and azimuth) trajectory control. In such applications, the sensors of the directional tool are also impaired by drilling induced vibration.
In all of the above applications, drilling induced vibrations can be of such severity that the sensor outputs saturate causing non-linearity, which cannot be processed by data acquisition and averaging techniques.
The oilfield well construction and utility industries use a range of commercially available servomechanism accelerometers for the measurement of the earth's gravitational field (G) and the industry standard for precision measurement is a flexible quartz hinge device. These are typically of a closed loop design whereby the current flowing in a correcting torquer coil is servoed to a proof mass position and the control attempts to maintain the proof mass in an equilibrium or null position. The magnitude of the torquer current is a measure of the G field vector acting on the accelerometer sensitive axis.
FIG. 1 shows part of a known circuit for processing the output from such an accelerometer A. Assuming that the accelerometer A is motionless, it outputs a steady current that is proportional to the acceleration along its sensitive axis. For drilling purposes in order to make the required directional readings of the tool, only the DC output from the accelerometer is of interest. The output current is converted into a measurable DC voltage via a precision resistor R1 and the voltage is subsequently measured by an analog-to-digital converter or ADC (not shown). During use, the temperature within the directional tool is also measured and is used to apply correction factors to the device and electronics. Three such accelerometers are installed in a directional instrument to measure the component of the gravitational field along each of the X, Y and Z axes of the tool as mentioned above. These accelerometers are calibrated and modelled following installation onto the instrument housing to ensure the magnitude and misalignment errors are minimised. Repeatable and predictable functioning of the accelerometers is therefore of critical importance to accurate modelling and measurement of G.
At present the drilling industry demands 0.1° accuracy in inclination measurements provided by each accelerometer. This level of accuracy means that a directional tool must be able to detect a change of 1 mG in the inclination of each accelerometer. Typical output currents from commercially available accelerometers are about 3.0 mA/G and this means that the circuitry that processes the output current must be able to resolve a change output current of the order to 3 μA.
The applicant has identified a particular problem in achieving this end. In particular, at present virtually all directional tools rely on ADC converters to sample the DC voltage generated by output current from the accelerometer through a precision resistor. Each ADC has a certain voltage capture range and a certain number of bits of resolution. A 12-bit resolution is common, although the problem is the same whatever the number of bits. In order to resolve at the required level, it is necessary to use at least one thousand quantisation levels for both positive and negative input voltages. Accordingly there is a minimum voltage input required to the ADC given by (1000/total number of quantisation levels) multiplied by the voltage capture range of the ADC.
For example, the MAX186 12-bit ADC is commonly used in directional tools. This has a capture range of ±2V and therefore the minimum input voltage from the circuit to achieve the desired resolution is ±0.98V˜±1V.
When drilling is stopped to take a survey measurement, the DC voltage from the circuit is stable and lies within the capture range of the ADC.
However, under vibration conditions (such as those caused when drilling with a steerable assembly), the output from each accelerometer is changed by the addition of a non-periodic AC-like waveform on top of the DC component. This AC waveform is caused by the variable torquer coil current needed to hold the proof mass steady in the null position under the vibration. Nevertheless, extraction of the DC component of acceleration is still possible within the frequency bandwidth capability of the sensing system. However, the applicant has found that with existing circuits tolerance to vibration above a few G is very poor. What happens is that the DC output from the circuit quickly moves outside the capture range of the ADC causing clipping of the DC output voltage and a rectification error, leading to a gravity toolface measurement that can be several tens of degrees off.
FIGS. 2 and 3 show the response of a directional tool employing the circuit shown in FIG. 1. The tool was oriented on the test rig so that the Z axis was horizontal, and the X and Y axis accelerometers were plus and minus 45° from horizontal respectively. The directional tool was subjected to sinusoidal oscillations in the vertical plane at 25 Hz at 5 g constant peak acceleration. In FIG. 2, the y-axis shows the vector sum (Gtot) of the acceleration outputs from each of the three accelerometers, versus time on the x-axis. Before vibration was started, the correct reading of 1 Gtot was output from the tool. As soon as vibration began, the output is offset to 0.4 Gtot, which is caused by vibration rectification error. As explained above this error arises because the output voltage from the circuit is greater than the voltage capture range of the ADC into which the DC voltage is input. Accordingly, the voltage is clipped by the ADC; the proportion of the signal that is clipped on each of the positive and negative side of waveform determines the direction and magnitude of the rectification error. FIG. 3 shows error in the tool high side output which indicates that the axis has been rotated through about 10°, when in fact the tool has not been rotated at all. In use, this measurement would be combined with the aforementioned angular offset to provide the tool face measurement. This would be incorrect by 10° causing the driller to stop drilling and apply a rotational correction to the string when in fact none is needed.
The semi-sinusoidal part of the offset FIG. 2 is an aliasing effect of the sampling carried out by the ADC during the experiment. In particular, the sampling rate was only 120 samples for the whole experiment that lasted about three minutes. Therefore, the sampling rate does not meet the Nyquist criterion and aliasing of the input frequency can be expected. Nevertheless, this is not important as the experiment demonstrates the problems of rectification error. Normally in downhole measurements the output signal from an accelerometer is sampled at some hundreds of kilohertz and the vibration experienced from drilling is normally of the order of 5-500 Hz and so such aliasing is not experienced in practice.
An improvement to the circuit of FIG. 1 is shown in FIG. 4 and this latter circuit has been used in the field for some time. The circuit of FIG. 4 uses a low impedance path comprising R2 and C2 in parallel with the torquer coil current sensing resistor R1. This has the effect of shorting to ground a significant portion of the frequencies in the AC component of the output signal.
FIGS. 5 and 6 show the results of an experiment on a directional instrument employing the circuit in FIG. 4. The experiment was the same as that performed using the circuit of FIG. 1. As is clearly seen the outputs Gtot and high side exhibit reduced vibration rectification error and thereby improved performance when gravity toolface measurements are taken during drilling.
Despite the improved performance, there are several problems with a circuit of the type shown in FIG. 4 and other circuits employing a similar principle of operation. In particular, the capacitance C2 needs to be of significant magnitude if its cut-off frequency (3 dB point) is to be low enough to remove most of the AC component. Typical capacitances required are of the order of 100-300 μF. Such a capacitance is often provided by a wet tantalum capacitor, which is physically quite large, for example 15 mm diameter by 30 mm length. That problem is compounded by the fact that wet tantalum capacitors are polarised and therefore two such capacitors are required per accelerometer (to accommodate the bipolar signal from the accelerometer), and therefore six such capacitors are needed for all three accelerometers. This uses up a considerable portion of the space available within the directional tool for the circuit. There is industry pressure to make tools smaller. For example, some conventional directional tools have to fit within a cylindrical space of diameter between 25 mm and 36 mm and length 304 mm (12″). Therefore, it is desirable if space savings can be made where possible.
A further problem is that the directional tool must work reliably over long periods of time within a wide range of temperatures, for example from −5° C. up to about 175° C. At elevated temperatures it has been found that electrolytic capacitors suffer internal leaks, which causes current leakage that is non-linear with temperature. This is highly undesirable as such effects cannot readily be compensated during signal processing.
A small improvement in the vibration tolerance of the tool could be achieved by using a greater resolution ADC (e.g. a 16-bit) so that the required number of quantization levels (e.g. one thousand) occupy a lesser percentage of range. However, this does not stop the clipping of the DC voltage and rectification errors persist.
Accordingly, there is a need for improved tool and instrument designs that overcome the problems or reduce the errors discussed above.